Electric power distribution systems are constructed either with overhead conductors or underground cables, but often composed of a combination of both. A distribution feeder is mainly composed of a circuit breaker, reclosers, line segments, busbars, service transformers, switches, and fuses. The topology of the distribution feeders typically has a fish-bone like structure to accommodate complex layouts of residential areas. The entire conductor length of a typical distribution feeder can stretch up to tens of miles or more, and comprise many small and large feeder segments. These lines are subject to short-circuit faults caused by insulation degradation, fallen trees, animal contact, etc. Following a fault, the utility company locates and isolates the fault, and dispatches a repair crew. This is often accomplished by patrolling the line emanating from the substation or towards the substation in search of the fault both for cause and location. The search process typically lasts hours and has an adverse impact on SAIDI (System Average Interruption Duration Index), which is a common reliability indicator used by electric power utilities.
One conventional outage management and crew dispatch method involves determining the location of a fault by placing a plurality of sensors on two or more branches of the power distribution system. The sensor can provide an indication if the fault current has passed through the corresponding branch e.g. by emitting detectable light or sound. When searching for the fault, the repair personnel follow the sensors which have indicated the fault path and locate the fault. The sensors have a unique identifier and can communicate to the control room the time of occurrence, so that the operator can locate the fault area and dispatch a repair crew.
In a second conventional approach, a distribution automation system includes a central control unit and feeder remote terminal units (RTUs) deployed along the lines. The RTUs receive measured voltage and current, compare the phase of a zero/positive-sequence voltage with the phase of a zero/positive-sequence current, and generate a fault indication when the phases satisfy certain conditions. When a fault occurs, the RTUs transmit the fault related information to the central control unit and the central control unit automatically identifies the faulty section and controls the open/closed status of the related RTUs to restore power to the healthy sections.
A third conventional approach discloses a control system that automatically identifies, locates, and isolates faults for a distribution system. The system includes a central computer and casings installed at pre-determined locations along the feeders. Each casing contains a radio transceiver, and an amplitude modulation (AM) detector. When a fault occurs, the two nearest AM detectors sense the radio noise produced by the fault and each sends a signal to the central computer. The central computer estimates the fault location by comparing the difference in the arrival time of the two signals. After the fault location is determined, the central computer sends a command to disconnect the two closest switches and isolate the faulted segment.
In each of these approaches, the faulted segment cannot be identified to the level between the two service transformers on the laterals. Another disadvantage is that they require extra devices on the feeder and the communication back to the control center.
Another conventional approach provides an impedance-based fault location method for a branched, non-homogeneous, and radial electric power distribution system. The fault location module is built within an intelligent electronic device (IED) and takes the voltage and current measurements from PTs (potential transformers) and CTs (current transformers) and calculates the reactance seen from the measuring point. The fault location module stores a look-up table with the reactance values from the substation to all buses in the feeder. By comparing the calculated reactance value with the values in the look-up table, multiple possible fault locations can be identified. If the IED can determine the fault type, the fault location module then removes the fault locations on the conductors that do not contain the faulted phases. Faulted circuit indicator information (FCIs) installed on the distribution system is communicated to the IED to further narrow down the candidate fault locations. However, this process is only applicable to radial networks. Furthermore, in order to narrow down the candidate fault locations, faulted circuit indicators information outside the substation are needed.
In another conventional approach, an algorithm which uniquely identifies the faulted node requires synchronized pre- and during-fault voltage and current phasors at the substation. The algorithm also requires voltage sag magnitudes recorded at selected IEDs along the feeder, which can be communicated back to the substation. The method sweeps all nodes in the network and performs load flow analysis iteratively for each node to calculate the voltage sags for the entire network. The true faulted node is the one that reveals the minimum difference between the calculated voltage sags and the measured sags. However, this approach is limited to radial topologies. Moreover, this method requires a detailed network model, load information, multiple IEDs deployed along the feeder and the communication link with the substation.
In systems with AMI (advanced metering infrastructure), the data from impacted meters must be retrieved, decrypted, aggregated, and analyzed on the AMI head-end. By design, multiple iterations are needed in what results as outage scoping analysis. Assuming all meters report timely and without failure, the end result is outage localization to the first protection component e.g. a fuse that operated to isolate the fault. When this information is available, the repair crew starts from that general area and, depending on the size and access/train characteristics of the area, may still take sizeable effort and time to finally narrow down the faulted segment.